Formation resistivity factor

This model (known as the SDR model) uses the log mean relaxation of 100% brine saturated rock as the estimator of the effective pore size [32]. This limits the method to rocks in the absence of hydrocarbons, which models permeability to be proportional to the porosity to the fourth power and log mean T2 to the second power, Eq. (3.6.6). Variations of this method use different exponents or the formation resistivity factor rather than porosity [2] ... 

This paper reports an investigation of the effects of porous solid structures on their electrical behaviour at different frequencies (from 100 Hz to 100 kHz). For that, we study different parameters such as formation resistivity factor, cementation factor, chargeability, resistivity index and saturation exponent. Different porous solid structures are quantified from the petrographic image analysis and Hg-injection technique. Then, by using different models we obtain the permeability prediction from the electrical behaviour and structure parameters. 

Chargeability factor M depends on the brine/gas saturation of porous solids. Figure 3 gives the relationship between the chargeability and brine saturation for two samples. We noted that the M decreases hardly with the decrease of the brine saturation. The presence of vugs and karsts pore types (sample 9-LS8) seems to speed up the decrease of the M Chargeability factor M can be explained by a multi-linear model composed of different structures parameters such as the formation resistivity factor, water porosity, Hg-specific surface area and water permeability, e.g.. Fig. 5. 

The ratio of the resistivity (R ) in sediment to the resistivity (R. ) in pore water defines the formation (resistivity) factor (F). (a) and (m) are constants which characterize the sediment composition. As Archie (1942) assumed that (m) indicates the consolidation of the sediment it is also called cementation exponent (cf. Sect. 3.2.2). Several authors derived different values for (a) and (m). For an overview please refer to Schon (1996). In marine sediments often Boyce s (1968) values (a = 1.3, m = 1.45), determined by studies on diatomaceous, silty to sandy arctic sediments, are applied. Nevertheless, these values can only be rough estimates. For absolutely correct porosities both constants must be calibrated by an additional porosity measurement, either on discrete samples or by gamma ray attenuation. Such calibrations are strictly only valid for that specific data set but, with little loss of accuracy, can be transferred to regional environments with similar sediment compositions. Wet bulk densities can then be calculated using equation 2.3 and assuming a grain density (cf. also section 3.2.2). 

Rock properties are computed from the micro, to plug and whole core scale. The absolute permeability, for example, can be computed using Lattice-Boltzmann simulations, while the calculation of the formation resistivity factor is based on a solution of the Laplace equation with charge conservation. The elastic properties are calculated with the finite element method. 

As a result of the proportionality between formation resistivity Rq and water resistivity in case of a water-saturated rock, Archie introduced the formation resistivity factor F ... 

The formation resistivity factor expresses the resistivity magnification relative to the conductor brine as a result of the presence of the non-conductive matrix (formation). 

MilUer-Huber, E., Schdn, J., Bdmer, F., 2015. The effect of a variable pore radius on formation resistivity factor. J. Appl. Geophys. 116, 173-179. 

The flowrate of oil into the wellbore is also influenced by the reservoir properties of permeability (k) and reservoir thickness (h), by the oil properties viscosity (p) and formation volume factor (BJ and by any change in the resistance to flow near the wellbore which is represented by the dimensionless term called skin (S). For semisteady state f/owbehaviour (when the effect of the producing well is seen at all boundaries of the reservoir) the radial inflow for oil into a vertical wellbore is represented by the equation ... 

Addition of up to 200 ppm sulfur dioxide to grape musts is customary. Strains of S. cerevisiae and S. bayanus grown in the presence of sulfite, become tolerant of fairly high concentrations of SO2. Cultures propagated in the winery are added in Hquid suspension, usually at 1—2% of the must volume. Many strains are available in pure culture. Factors such as flocculence, lack of foaming, fast fermentation, lack of H2S and SO2 formation, resistance to sulfur dioxide and other inhibitors, and flavor production will affect strain choice. No strain possesses all the desired properties. 

Polyacrylamide El, with the lowest electrochemical degradation factor of 11.2 in Table 3, experiences the smallest reduction of resistance factor in the presence of univalent and divalent electrolytes, from 55.9 in river water to 49.5 in an 80/20 mixture of river and formation waters. These unusually large resistance factors probably resulted from the hydrodynamic resistance of the long linear polymer chain which is a unique characteristic of its gamma radiation manufacturing process. There appears to be some correspondence between the effect of electrolytes on viscosity and screen factor since polymers C and D1 with the lowest electrochemical degradation exhibit the greatest reduction in screen factor on... 

Polyacrylamide El exhibits the highest active and residual resistance factors (45.6 and 32.2 respectively) of the polymers tested. Polyacrylamide El also exhibited the highest resistance factors in river water and in a mixture of river and formation waters. The transient resistance factor and normalized concentration curves as a function of pore volumes injected are illustrated... 

The resistance factor at field rates (e.g., 1 ft/day) can be calculated since the shear rate is directly proportional to the flooding velocity and the logarithm of viscosity is directly related to the logarithm of shear rate. The shape of the resistance factor curves for the xanthan gum in formation brine indicates... 

Fig. 11. Resistance factors and concentrations of Polymer E2 in reservoir core at 95°F with 100% formation brine in the connate water and in the injected solution.

Fig. 12. Resistance factor of dilute polysaccharide solution from reservoir cores (Waltersburg Formation) at 75 2°F.

Polyacrylamides such as C and D which had high electrochemical degradation factors, exhibited plugging behavior and low resistance factors in the reservoir cores which were presaturated with formation brine. 

Polysaccharide G2 had an unusually high residual resistance factor (9.3) and retention (321 lbs/acre-foot) in an 80/20 mix of river/formation waters. The high retention and resistance factor resulted from mechanical entrapment of microgels (reversible complexes of divalent cations with polysaccharide molecules) formed in the 80/20 mixture of river and formation waters. Further testing in 100% formation water indicated higher retention (542 Ibs/acre-foot) in the reservoir cores. Correspondent increases in milli-pore filter ratios and filtration times were observed to occur with increase of univalent and divalent electrolytes. 

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